General Documentation Template

2016–2017 Local Idaho Power Transmission Plan Delivery Planning

Idaho Power Company Draft 2016–2017 Local Transmission Plan

TABLE OF CONTENTS

Table of Contents ...... i

List of Tables ...... ii

List of Figures ...... iii

List of Appendices ...... iv

1. Introduction ...... 1

1.1. Local Planning ...... 1

1.2. Regional and Interconnection-Wide Coordination ...... 1

2. Planning Process and Time Line...... 2

3. Transmission System Plan Inputs and Components ...... 3

3.1. Idaho Power’s Transmission System ...... 3

3.2. Load Forecast ...... 3

3.2.1. Western Load Area ...... 5

3.2.2. Treasure Valley Load Area ...... 5

3.2.3. Southern Load Area ...... 6

3.2.4. Eastern Load Area...... 7

3.3. Forecasted Resources ...... 8

3.4. Transmission Use Forecast ...... 9

3.5. Area Planning ...... 10

3.6. Economic studies ...... 17

4. System Conditions Studied ...... 18

4.1. Scenarios Studied ...... 18

4.2. Transmission System Model ...... 18

5. Reliability Evaluation ...... 19

5.1. Transmission System Analysis ...... 19

5.2. 2021 Heavy Summer Study Results...... 20

5.3. 2026 Heavy Summer Study Results...... 20

5.4. 2026 NTTG Heavy Winter Case Study Results...... 21

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5.5. 2036 Heavy Summer Study Results...... 21

6. Summary and Conclusions ...... 23

LIST OF TABLES

Table 1 Meeting dates and descriptions ...... 2

Table 2. Load forecasts for areas of Idaho Power (1 in 2 peak) ...... 4

Table 3 2015 IRP Preferred Portfolio ...... 8

Table 4 Summary of resources in 2016 Q1 Idaho Power Interconnection Queue with Executed PSAs ...... 8

Table 5 Transmission Service Obligations submitted in Quarter 5 ...... 9

Table 6 Comparison of 2036 Transmission Needs with Expected TTC for various RTPs ...... 9

Table 7 Modeled loads in 2036 power flow case (1 in 10 peak) ...... 18

Table 8 Summary of performance criteria issues ...... 20

Table B-1 Projects planned for 1-5 year horizon ...... 29

Table B-2 Projects planned for 5-10 year horizon ...... 30

Table B-3 Projects planned for 10-20 year horizon ...... 32

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LIST OF FIGURES

Figure 1 Planning cycle schedule ...... 2

Figure 2 Idaho Power transmission system ...... 3

Figure 3 Idaho Power load areas ...... 4

Figure 4 Western load area ...... 5

Figure 5 Treasure Valley load area ...... 6

Figure 6 Southern load area ...... 7

Figure 7 Eastern load area ...... 7

Figure 8 Treasure Valley electrical plan ...... 10

Figure 9 Magic Valley electrical plan ...... 11

Figure 10 Wood River Valley electrical plan ...... 11

Figure 11 Eastern Idaho electrical plan ...... 12

Figure 12 Western Treasure Valley electrical plan ...... 13

Figure 13 Eastern Treasure Valley electrical plan—Ada County ...... 14

Figure 14 Eastern Treasure Valley electrical plan—Elmore County ...... 15

Figure 15 West Central Mountains electrical plan—Valley County...... 16

Figure 16 West Central Mountains electrical plan—Adams County ...... 17

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LIST OF APPENDICES

Appendix A Community Advisory Committee Process ...... 25

Appendix B Twenty-year project list ...... 29

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Idaho Power Company Draft 2016–2017 Local Transmission Plan

1. INTRODUCTION

The 2017 Local Transmission Plan is the culmination of the 2016-2017 local transmission planning process as described in Idaho Power’s Open Access Transmission Tariff (OATT) Attachment K. The plan includes all transmissions system facility improvements identified through this planning process. A power flow reliability assessment of the plan was performed which demonstrated that the planned facility additions will meet NERC and WECC reliability standards.

Idaho Power’s OATT is located on its Open Access Same-time Information System (OASIS) at http://www.oatioasis.com/ipco. Additional information regarding Transmission Planning is located in the Transmission Planning folder on Idaho Power’s OASIS. Unless otherwise specified, capitalized terms used herein are defined in either Section 1 of Idaho Power’s OATT or Section 1 of Idaho Power’s OATT Attachment K. 1.1. Local Planning

This Local Transmission Plan (LTP) has been prepared within the two-year process as defined in Idaho Power’s OATT Attachment K. The LTP identifies the Transmission System facility additions required to reliably interconnect forecasted generation resources and serve the forecasted Network Customers’ load, Native Load Customers’ load, and Point-to-Point Transmission Customers’ requirements, including obligations for rollover rights, over a twenty (20) year planning horizon. Additionally, the LTP incorporates any stakeholders requested economic congestion studies results. Links to documents related to the LTP are located in the Local Transmission Plan folder on Idaho Power’s OASIS site. 1.2. Regional and Interconnection-Wide Coordination

Idaho Power coordinates its planning processes with other transmission providers through membership in Northern Tier Transmission Group (NTTG) and the Western Electric Coordinating Council (WECC). Idaho Power uses the NTTG process for regional planning, coordination with adjacent sub-regional groups and other planning entities, and development of proposals to WECC for interconnection-wide planning. Additional regional coordination information is located in Idaho Power’s OATT Attachment K and on the NTTG’s website at www.nttg.biz.

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2. PLANNING PROCESS AND TIME LINE

This plan is for the 2016–2017 planning cycle. The planning cycle schedule is shown below in Figure 1.

Figure 1 Planning cycle schedule

Idaho Power holds webinar meetings throughout the planning cycle to keep stakeholders and interested parties informed. The following table lists the meeting dates.

Table 1 Meeting dates and descriptions

Date Meeting Meeting Description 3/16/2016 2016-2017 1st Quarter Idaho Power Local Transmission Plan Request for Information 6/16/2016 2016-2017 2nd Quarter Idaho Power Local Transmission Plan Presentation of assumptions 9/21/2016 2016-2017 3rd Quarter Idaho Power Local Transmission Plan Initial analysis results 12/21/2016 2016-2017 4th Quarter Idaho Power Local Transmission Plan Results / draft report 3/15/2017 2016-2017 5th Quarter Idaho Power Local Transmission Plan Request for information 6/21/2017 2016-2017 6th Quarter Idaho Power Local Transmission Plan Analysis results / draft report 9/20/2017 2016-2017 7th Quarter Idaho Power Local Transmission Plan Final report 12/20/2017 2016-2017 8th Quarter Idaho Power Local Transmission Plan Final report

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3. TRANSMISSION SYSTEM PLAN INPUTS AND COMPONENTS 3.1. Idaho Power’s Transmission System

Idaho Power’s transmission system exists mostly in southern Idaho and eastern Oregon. The system extends north to the Montana border, east into Wyoming to the Jim Bridger power plant, south to Wells, Nevada (not shown), and west to LaGrande, Oregon, Walla Walla, Washington, and Summer Lake, Oregon as shown in Figure 2.

Figure 2 Idaho Power transmission system 3.2. Load Forecast

Idaho Power produces a forecast of native and network loads for its balancing area. This forecast includes Idaho Power’s twenty-year load forecast and a 20 year network customer load forecast based on Bonneville Power Administration’s ten-year forecast and PacifiCorp’s ten-year forecast. The load forecasts include expected energy efficiency reductions.

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Table 2, below, lists the load forecasts for the Western and Treasure Valley, Southern and Eastern load areas based on load forecasts established during quarter 1 of the process. Idaho Power generally divides its service territory into four load areas; however the load forecast reporting for the Western and Treasure Valley load areas are combined as their geographic areas overlap.

Table 2. Load forecasts for areas of Idaho Power (1 in 2 peak)

Area Description Load Level Western and Treasure Valley Idaho Power’s system west of Mountain Home 2,894 MW Southern Idaho Power’s system bounded by Mountain Home on the west and 1,307 MW American falls on the east. Eastern Idaho Power’s system east of American Falls 518 MW

A transmission map with the load areas presented in Table 2 is shown below in Figure 3.

Eastern

ONTARIO Western CALDWELL BOISE

BLACKFOOT MOUNTAIN HOME

Treasure Valley POCATELLO

Legend TWIN FALLS Operating Voltage 138kV 161kV 230kV 345kV 500kV Southern

Figure 3 Idaho Power load areas

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The following sub-sections will present further information on Idaho Power load areas. 3.2.1. Western Load Area

The Western Load Area includes Malheur County in Oregon and Payette, Valley, and Washington counties in Idaho. The area also includes the Brownlee East (Path 55) and Idaho to Northwest (Path 14) WECC transmission paths. The Western load area, including the area substations, generation facilities and transmission paths is shown in Figure 4.

Figure 4 Western load area 3.2.2. Treasure Valley Load Area

The Treasure Valley Load Area includes the Idaho counties of Ada, Boise, Canyon, Elmore, and Gem. The Treasure Valley load area, including the area substations, generation facilities and transmission paths is shown in Figure 5.

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Figure 5 Treasure Valley load area 3.2.3. Southern Load Area

The Southern Load Area includes the Idaho counties of Blaine, Cassia, Gooding, Jerome, Lincoln, Minidoka, and Twin Falls. The area also includes the Idaho to Sierra (Path 16) WECC rated transmission path and the Midpoint West internally monitored transmission path. The Southern load area, including the area substations, generation facilities and transmission paths is shown in Figure 6.

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Figure 6 Southern load area 3.2.4. Eastern Load Area

The Eastern Load Area includes the Idaho counties of Bannock, Bingham, and Power. The area also includes the Borah West (Path 17) WECC rated transmission path. The Eastern load area, including the area substations and transmission paths is shown in Figure 7.

Figure 7 Eastern load area

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3.3. Forecasted Resources

Table 3 contains the preferred resource portfolio for the next 20 years as presented in Idaho Power’s 2015 IRP.

Table 3 2015 IRP Preferred Portfolio

Date Resource Capacity 2025 Boardman to Hemingway 500 MW Transfer Capacity 2025 Retire North Valmy (both units) (262 MW) 2030 Demand Response 60 MW 2030 Ice-based thermal energy storage 20 MW 2031 CCCT 300 MW

The 2015 IRP can be found on the Idaho Power website: https://www.idahopower.com/AboutUs/PlanningForFuture/irp/default.cfm Table 4 contains a summary of resources in 2016 Q1 IPCO interconnection queue with executed power sales agreements.

Table 4 Summary of resources in 2016 Q1 Idaho Power Interconnection Queue with Executed PSAs

Resource Capacity (MW) Hydro 27 Wind 50 Solar 310

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3.4. Transmission Use Forecast

In Quarter one, Idaho Power submitted transmission service obligations (―TSOs‖) to NTTG. Table 5 below shows these transmission service obligations.

Table 5 Transmission Service Obligations submitted in Quarter 5

Transmission WECC Path Point of Point of Obligation Number/ Submitted By Receipt Delivery Start Date End Date (MW) Direction Idaho Power Northwest IPCO 1/1/2022 - 500 (summer) 14 W-E 200 (winter) 82 W-E BPA Northwest BPA SEID 1/1/2022 12/31/2028 250 (summer) 14 W-E 550 (winter) 82 W-E 17 W-E

Table 6 is a comparison of the 2036 transmission capacity needed ("TCN") from Table 5 with TTCs of the critical paths with and without the Boardman to Hemingway 500 kV transmission project (―B2H‖). The TTCs are based on Path Rating Studies performed for the B2H project. Numbers in red indicates a deficiency in meeting the transmission needs on the path. Green numbers are those which have sufficient capacity to meet the transmission needs.

Table 6 Comparison of 2036 Transmission Needs with Expected TTC for various RTPs

WECC Path Number/ 2036 Transmission 2036 TTC 2036 TTC Direction Capacity Needed (MW) (w/ B2H) (w/o B2H) 14 W-E 1950 2250 1200 82 W-E 3065 3515 2465 17 W-E 705 1600 1600

The results of this comparison illustrate the need for the B2H project.

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3.5. Area Planning

Idaho Power develops long-term local area transmission plans with regional community advisory committees. These committees consist of jurisdictional planners; mayors; council members; commissioners; and large industry, commercial, residential, and environmental representatives. The plans identify the transmission and substation infrastructure required through the full development or ―build-out‖ of the local area. The Treasure Valley, Western Treasure Valley, Eastern Treasure Valley, Magic Valley, Wood River Valley, and Eastern Idaho electrical plans have been completed. Figures 9 through 15 present the future transmission infrastructure plans for each of the aforementioned electrical plans. A description of the community advisory committee process can be found in Appendix A.

More information about electrical plans can be found on the Idaho Power website at: http://www.idahopower.com/AboutUs/PlanningForFuture/RegionalElectricalPlans/default.cfm

Figure 8 Treasure Valley electrical plan

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Figure 9 Magic Valley electrical plan

Figure 10 Wood River Valley electrical plan

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Figure 11 Eastern Idaho electrical plan

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Figure 12 Western Treasure Valley electrical plan

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Figure 13 Eastern Treasure Valley electrical plan—Ada County

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Figure 14 Eastern Treasure Valley electrical plan—Elmore County

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Figure 15 West Central Mountains electrical plan—Valley County

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Figure 16 West Central Mountains electrical plan—Adams County 3.6. Economic studies

Eligible customers or stakeholders may submit an economic congestion study request during either quarter 1 or quarter 5 of the planning cycle. Idaho Power did not receive any study requests during quarter 1 of the 2016-2017 planning cycle.

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4. SYSTEM CONDITIONS STUDIED 4.1. Scenarios Studied

Idaho Power uses scenario planning to evaluate the performance of the transmission system for different load and generation dispatch patterns in the future. A 20 year heavy summer load study case was evaluated as the primary study scenario.

A five year heavy summer load scenario and a 10 year heavy summer load scenario were also studied. These cases were selected to assess future system adequacy and performance.

Further, a 10 year base case developed from WECC TEPPC production cost model data through NTTG was also evaluated to determine if any unusual flow pattern exists that is not represented in the selected seasonal cases. A winter condition with heavy load in the Idaho area was selected. 4.2. Transmission System Model

The 20 year power flow case was based on the WECC 2026 HS1 base case, approved by WECC on April 11, 2016. Load levels in the 20 year case were increased to approximate Idaho Power’s forecasted control area load in the year 2036. The total Idaho Power control area load was scaled up from the forecasted 2036 level to model a 1 in 10 year peak. The load modeled was approximately 4,889 MW. This is roughly a 1,100 MW increase in load from Idaho Power’s historical area peak load, including Network Customer load, of 3,750 MW, which occurred on July 2, 2013. The loads in the case were increased to approximately achieve the distribution across the Idaho Power’s system noted below in Table 7.

Table 7 Modeled loads in 2036 power flow case (1 in 10 peak)

Area Description Load Level Western and Treasure Valley Idaho Power’s system west of Mountain Home 2,998 MW Southern Idaho Power’s system bounded by Mountain Home on the west and 1,354 MW American falls on the east. Eastern Idaho Power’s system east of American Falls 537 MW

The 20 year power flow case was also modified to reflect the expected 500 kV transmission improvements for the Gateway West and Boardman to Hemingway (B2H) transmission projects. Lower voltage transmission modeling detail was added to the Idaho Power service territory that was not originally modeled in the WECC base case. Transmission growth and reliability driven projects that have been planned for the next 20 years have also been added to the case. A list of projects scheduled for the next 20 years can be found in Appendix B.

The five year and ten year scenarios utilized WECC approved power flow cases. Idaho Power evaluated the same cases as part of its 2016 NERC TPL compliance reliability evaluation. The following two WECC cases were utilized:

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 2021 Heavy Summer case (21hs2 ), approved 10/21/2015  2026 Heavy Summer case (26hs1), approved April 11, 2016

The load, resource dispatch and path flow data modeled in the WECC base cases for the five and ten year cases were not modified from the WECC published cases.

The 2026 heavy winter NTTG base case utilized WECC TEPPC 2026 production cost model data. The TEPPC 2026 model is a security constrained economic-commitment-and-dispatch model based on forecasted loads and resources for the year 2026 that were submitted from all WECC balancing authorities. The balancing authorities supply monthly peak and energy forecasts. The forecasts are then dispersed into hourly load demands.

After reviewing the hourly 2026 production cost data, the model data for a heavy winter load hour was extracted into a PowerWorld power flow model by the Northern Tier Transmission Group (NTTG) Technical Work Group (TWG) for its 2016-2017 planning process. The extracted case was selected by the NTTG TWG because it represented an NTTG footprint heavy load condition.

5. RELIABILITY EVALUATION 5.1. Transmission System Analysis

PowerWorld power flow software was utilized to perform contingency analysis on each of the cases. Single element outage contingencies (N-1) were evaluated based on single transmission line, single transformer, or bus outages on systems 100kV or higher. Outages of Bulk Electric System (BES) classified generator units were studied. Two element outage (N-2) common structure outages were also evaluated.

The power-flow simulation results are measured against North American Electric Reliability Council (NERC) and WECC reliability criteria. Specifically, the NERC Reliability Standard TPL-001-4 requires that transmission facilities maintain operation within normal and emergency limits. The WECC criterion TPL-001-WECC-CRT-3 establishes the voltage violation thresholds for N-1 and N-2 contingencies. The NERC and WECC criteria formed the criteria for which every N-1 and N-2 contingency was screened.

Every N-1 contingency was screened for thermal overloads and voltage issues. Thermal overloads over 100% of equipment emergency ratings were reported. Voltage deviations greater than 8% were reported for category N-1 P1 events. A low voltage violation threshold was set for 0.90 PU and a high voltage threshold was set for 1.10 PU for all N-1 events.

Each N-2 contingency was screened for thermal overloads and voltage issues. Thermal overloads over 100% of equipment emergency ratings were reported. Voltage screening thresholds of 0.90 per unit and 1.10 per unit were utilized.

A summary of results can be found below in Table 8 and the results are discussed further in the following sections. The system improvements identified for the next 20 years are presented in Appendix B.

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Table 8 Summary of performance criteria issues

Number of Contingencies Case w/violations Thermal Issues Voltage Issues 2021 Heavy Summer 8 8 0 2026 Heavy Summer 9* 9 1 2026 NTTG Heavy Winter 0 0 0 2036 Heavy Summer 13 5 8 * A contingency in the 2026 Heavy Summer case had both a thermal issue and a voltage issue. 5.2. 2021 Heavy Summer Study Results

The 2021 heavy summer case resulted in eight flagged contingencies with thermal overload violations.

Four of the violating thermal overload contingencies were clustered in the Ontario area. The proposed solution to address these overloads is to install a remedial action scheme to bypass a series capacitor or open a 138kV line to relieve the overloads.

In the Boise area, two of the violating contingencies were breaker failure contingencies that resulted in thermal overloads. The proposed solution to address the potential overloads is a project to wrap the Boise Bench – Locust 230kV line into Cloverdale and install a 230/138kV transformer at Cloverdale substation.

The N-2 loss of a common structure 138kV line in the Boise area was identified as a violating contingency. The proposed solution to address this contingency is a project to wrap the Boise Bench – Locust 230kV line into Cloverdale, install a 230/138kV transformer at Cloverdale substation, and install a line circuit breaker with line relaying at Joplin.

The N-2 loss of a common structure 230/138kV line in the Treasure Valley was also indentified as violating contingency. The proposed solution is a project to construct a 230kV line from Hubbard to Cloverdale in addition to the previously mentioned 230/138kV transformer installation project at Cloverdale. 5.3. 2026 Heavy Summer Study Results

The 2026 peak summer load case resulted in nine flagged contingencies, all of which were deemed criteria violations.

The loss of a Boise area 138 kV line results in an overload on another 138 kV line. The proposed solution to address the overload is to install a 230/138kV transformer at Cloverdale substation.

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Three thermal overload contingencies were clustered in the Ontario area. The proposed solution is to install a remedial action scheme to either bypass a series capacitor or open a 138kV line to relieve the overloads.

A 138kV bus outage in the Southern Idaho load area resulted in low voltage at several load busses and an overload of a transformer. The proposed solution is to install a larger 230/138kV transformer at Midpoint station.

The N-2 loss of a common structure 230kV/138kV line in the Treasure Valley was also indentified as violating contingency. The proposed solution is a project to construct a 230kV line from Hubbard to Cloverdale in addition to a previously mentioned 230/138kV transformer installation project at Cloverdale. 5.4. 2026 NTTG Heavy Winter Case Study Results

No thermal or voltage issues in the Idaho Power system resulted from the N-1 and N-2 contingency analysis in the 2026 Heavy Winter NTTG case. Contingencies evaluated by NTTG were limited to circuits 200kV and above. 5.5. 2036 Heavy Summer Study Results

The 2036 peak summer load case resulted in 13 flagged contingencies.

The 2036 case also included all the sub-transmission system elements less than 69kV. Contingencies ran on this case were limited to single transmission line, single transformer, single generator unit, or N-2 common structure outages on elements greater than 100kV.

For both pre and post contingency, low voltages and overloads were present on the sub- transmission 46kV system in Eastern Idaho. The proposed solution is to move the Blackfoot station load from the 46kV bus to the 138kV bus and to build a new 161kV line from Haven to tap the Antelope-Goshen 161kV line.

In the Southern load area low voltage violations were found on the 46kV system for various 138kV contingencies. The proposed solution is to construct a 138kV line into the Shoshone station tapped from the Midpoint – Twin Falls 138kV line.

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A thermal contingency was flagged in the Ontario area. The proposed solution to address these overloads is to install a remedial action scheme to bypass a series capacitor or open a 138kV line to relieve the overload.

A N-2 common structure loss of two transmission lines indicates that a system upgrade will be required to integrate the 300 MW CCCT IRP resource into the system. This study assumed the generation would be installed at Langley Gulch. A proposed solution is a 230kV line from Langley Gulch to Garnet station. Garnet station will include a 230/238kV transformer and a 138kV line to tap into the Willis – Lansing 138kV line.

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6. SUMMARY AND CONCLUSIONS

Idaho Power’s Local Transmission Plan has been prepared as part of the two-year process defined in Idaho Power’s OATT Attachment K. The Plan has identified the transmission system facility additions required to reliably interconnect forecasted generation resources, serve Native Customer and Network Customer forecasted load and Point-to-Point Transmission Customers’ requirements over a twenty (20) year planning horizon.

An analysis of forecasted transmission service obligations was performed to determine whether additional transmission capacity is needed to meet forecasted use. A power flow reliability assessment was performed on cases modeling system facilities and conditions 5, 10, and 20 years into the future. The results of the transmission obligation analysis and reliability analysis triggered the following projects:

 Construct new Boardman to Hemingway 500kV line and associated Treasure Valley integration projects  Build new Willis-Star 138kV line  Add 230/138kV transformer at Cloverdale substation  Construct 230kV line from Hubbard to Cloverdale substation  Build the Haven Tap 161kV line in Eastern Idaho  Construct the Shoshone 138kV source line  Add 230kV line from Langley to Garnet for CCCT resource

A complete list of the significant facility additions and upgrades that have been identified to reliably interconnect forecasted generation resources, serve Native Customer and Network Customer forecasted load and Point-to-Point Transmission Customers’ requirements over a 20 year planning horizon are included in Appendix B.

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Appendix A Community Advisory Committee Process 1. Background

The process develops a plan to meet needs through build out, regardless of when that occurs. The process is possible due to an effective collaboration driven by significant commitment from both Idaho Power and the specific area ―community‖. Idaho Power dedicates significant skilled staff resources through the integral participation of planners and engineers to support the technical needs of the process. The unique community needs, interests and goals are represented through the Community Advisory Committee; a broad-based participation of elected officials, businesses, landowners, planners, agencies and other key stakeholders. The result is an effective blend of technical and non-technical input, combined to develop an electrical plan that is both technically sound and sensitive to each area’s needs. 2. Purpose of the Electrical Plan Process

To create a clear and documented electrical energy supply plan to serve the load needs of the area from now through build out.

The public process is the starting point of all electrical supply plans and any resulting transmission rights-of-way and substation siting requirements 3. The Planning Process

The planning process follows a specific outline of steps, divided into three basic components; education, infrastructure siting and plan implementation. The overall process typically involves 9 to 12 months beginning with education, followed by development of community criteria and alternatives, to a committee consensus decision for the final plan. Committee input is focused on two primary areas; where to, and where not to locate new infrastructure such as transmission lines, substations, etc. to be acceptable to the ―community‖, and recommendations for related delivery, conservation and demand-side management programs to support desired implementation of electrical service in the area. In general, the planning process does not address recommendations for electrical generation or future high voltage (500kV) transmission lines to move electricity into and through the region. 4. Typical Planning Steps

Meeting 1: Bus Tour  Committee orientation and ground rules  Idaho Power introduction and overview  Electric Power 101  Idaho Power voltage levels Meeting 2: Education  Generation  Transmission—including Gateway West, etc.

 Substation

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Meeting 3: Education  Rates and regulatory (continued)  Demand side management (energy efficiency)  Planning area existing electrical system conditions  Begin developing community criteria Meeting 4: Education  Confirm community criteria (continued)  Future electrical build out needs  Transmission & related components to meet build out needs  Initial alternative discussion Meeting 5: Infrastructure  Review of community criteria Mapping  Mapping/alternatives development orientation  Small group mapping exercises Meeting 6: Mapping  Mapping/alternatives development review and feedback and Evaluation  Resume mapping exercises if needed  Evaluation/scoring matrix orientation Meeting 7: Preferred  Alternatives evaluation and scoring process Alternatives  Identify preferred alternatives for each of the planning areas Meeting 8: Plan Consensus  Verify/confirm preferred alternative(s) and ranking  Develop implementation plan  Discuss local plans coordination Meeting 9: Plan Document  Review draft plan and Next Steps  Comments  Plan rollout discussion

5. The Community Advisory Committee

The Community Advisory Committee for each of the Electrical Plans includes individuals, representing a broad cross section of elected officials, local governments, businesses, community development organizations, planning entities, landowners, affected agencies, environmental organizations, and other key stakeholders. Together, they provide both individual and regional perspective regarding the key issues and concerns that are important to the specific area residents when meeting the long-term electrical needs for that area.

5.1.1. Advisory Committee Purpose Develop consensus support and lend credibility for identified electrical energy supply improvements necessary to serve the area.

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5.1.2. Advisory Committee Role Propose ideas and solutions to Idaho Power’s load serving needs that meet the area through build out. 6. Benefits and Uses of the Plan

The development of the Electrical Plans provide two primary benefits; First, the completed document outlines a specific plan based on community goals, with a range of acceptable alternatives for Idaho Power to follow as it implements specific infrastructure projects to meet the area’s electrical needs through build out. Second, the planning process develops significant community awareness and support that is critical to successful project development that is acceptable to community residents.

In addition to its use by Idaho Power, the plan is also intended for use by local jurisdictions, governments and affected agencies through incorporation into local planning documents. The plan is also a key tool for use by economic development organizations in support of existing and potential new businesses to the region. Finally, it is important to note that the plan is intended to be a living document, that can be adjusted with additional advisory committee and community input to respond to significant changes in electrical needs of the area. 7. Summary of Community Plans

Electrical Plans Year Completed Updates Year Updated Treasure Valley Electric Plan 2006 Revised for Birds of Prey Area 2007 Wood River Electric Plan 2007 Ongoing Magic Valley Electric Plan 2008 Planned for 2018 Eastern Idaho Electric Plan 2009 Planned for 2019 Western Treasure Valley Electrical Plan 2011 Planned for 2021 Eastern Treasure Valley Electrical Plan 2012 Planned for 2022 West Central Mountains Electrical Plan 2014 Planned for 2024

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Appendix B Twenty-year project list

Table B-1 Projects planned for 1-5 year horizon

Region Time Frame Project Title Project Scope Southern 5 year Rebuild 138 kV line from Moonstone to Wood River Rebuild existing 138 kV line between Moonstone and Wood River to improve reliability and performance to the Wood River loop. Treasure Valley 5 year Willis-Star 138 kV line Build a new approximately 11 mile 138 kV transmission line between Willis and Star to improve reliability in the area.

Eastern 5 year Build new City Center distribution substation Construct new 138-12.5kV distribution substation in Pocatello area. Treasure Valley 5 year Add 230/138 kV capability at Cloverdale Add a 230 kV line terminal and T231 230/138 kV 300 MVA transformer in the north side of the station. Treasure Valley 5 year Add line breaker and relaying at Joplin Add a line breaker and relaying at Joplin to create a new line terminal to remove the normal open. Western 5 year Install a RAS scheme at Ontario to relieve overloads Install a RAS scheme at Ontario to relieve overloads

Treasure Valley 5 year Build new Beacon Light Substation Build new Beacon Light distribution substation in the area northwest of Eagle. Treasure Valley 5 year Star-Beacon Light – Build new 138 kV line Extend 138 kV line approximately 2 miles to new Beacon Light substation. Treasure Valley 5 year Build new CanAda distribution substation Construct a new 138-12.5 kV distribution substation near CWI. Build 138kV tap to Zilog-Blackcat 138kV line.

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Table B-2 Projects planned for 5-10 year horizon

Region Time Frame Project Title Project Scope NTTG 10 year Boardman to Hemingway 500 kV Line Build a new 500 kV transmission line from Boardman, Oregon area to Idaho Power’s Hemingway substation. Treasure Valley 10 year Hemingway-Bowmont Build 230 kV line Add the second 230 kV line circuit on existing structures from Hemingway to Bowmont to integrate B2H project into Treasure Valley. Treasure Valley 10 year Hubbard-Bowmont Build 230 kV line Build a 230kV line from Hubbard to Bowmont to integrate B2H project into the Treasure Valley.

NTTG 10 year Gateway West 500 kV Line – Bridger to Populus Build a new 500 kV transmission line from Jim Bridger station in Wyoming to Populus station in Southeastern Idaho. NTTG 10 year Gateway West 500 kV Line – Populus to Borah Build a new 500 kV transmission line from Populus Station in Southeastern Idaho to Borah Station in Southeastern Idaho. NTTG 10 year Gateway West 500 kV Line – Populus to Cedar Hill Build a new 500 kV transmission line from Populus Station in Southeastern Idaho to Cedar Hill Station in Southern Idaho.

NTTG 10 year Gateway West 500 kV Line – Borah to Midpoint Convert the existing 345kV line between Borah and Midpoint (part of Kinport-Midpoint 345kV line) to 500 kV. Add new 345kV line terminal at Borah to terminate 345kV line from Kinport. NTTG 10 year Gateway West 500 kV Line – Cedar Hill to Midpoint Build a new 500 kV transmission line from Cedar Hill Station in Southern Idaho to Midpoint Station in Southern Idaho. NTTG 10 year Gateway West 500 kV Line – Cedar Hill to Build a new 500 kV transmission line from Cedar Hill Hemingway Station in Southern Idaho to Hemingway Station in Southwestern Idaho. Southern 10 year Replace 230/138 kV transformer at Midpoint with 300 Replace 200 MVA 230:138 kV transformer with a MVA 300MVA at Midpoint to relieve overload concerns.

Page 30 Draft 2016–2017 Local Transmission Plan Idaho Power Company Appendix B

Region Time Frame Project Title Project Scope

Eastern 10 year Add 161/138kV transformer at Haven Install a 161/138kV transformer at Haven and build a new 161kV line from Haven to tap point on Goshen- Antelope 161kV line.

Treasure Valley 10 year Build Hubbard-Cloverdale 230kV line Construct a new 230kV line from Hubbard to Cloverdale station.

Southern 10 year Upgrade Shoshone station to 138 kV Convert Shoshone station from 46 kV to 138 kV, build new 138kV line from tap near Midpoint on the Midpoint-Twin Falls line to Shoshone substation. Treasure Valley 10 year Build new Lakeshore distribution substation Construct new 138-12.5 kV distribution substation south of Nampa near Lake Lowell. Treasure Valley 10 year Build new 138 kV line from Lowell Junction to new Build a 138 kV transmission line to serve the new Lakeshore substation Lakeshore substation south of Nampa near Lake Lowell. Treasure Valley 10 year Build new Columbia distribution substation Build new 138-12.5kV distribution substation near Columbia and Meridian Roads. Treasure Valley 10 year Build radial 138kV line from Mora to Columbia Build radial 138kV transmission line from Mora to serve new Columbia station.

Draft 2016–2017 Local Transmission Plan Page 31 Appendix B Idaho Power Company

Table B-3 Projects planned for 10-20 year horizon

Region Time Frame Project Title Project Scope

Treasure Valley 20 year Build CanAda - Blackcat 138kV line Build new 138kV transmission line from CanAda substation to Blackcat substation Eastern 20 year Move Blackfoot distribution load to 138kV bus Move Blackfoot distribution transformer load from the 46kV to the Blackfoot 138kV bus Eastern 20 year Convert Tyhe Substation load to 138kV Convert Tyhe Substation load to 138kV

Treasure Valley 20 year Build new Wagner distribution substation Construct new 138-12.5 kV distribution substation in the area of Farmway and Purple Sage Road Treasure Valley 20 year Build Langley to Garnet 230kV line to integrate Convert Langley to Wagner Tap line to 230kV and CCCT resource build new 230kV line from converted 230kV line section to Garnet. Treasure Valley 20 year Build Garnet 230/138kV station Build substation at Garnet with 230/138kV transformer. Treasure Valley 20 year 138kV Garnet Tap Line Build 138kV line from Garnet to tap into the Willis to Lansing 138kV line.

Page 32 Draft 2016–2017 Local Transmission Plan Idaho Power Company Appendix B

Thank you for your interest.

2012–2013 Local Transmission Plan Page 33